EX-13 16 aep10kfrex1320174q.htm ANNUAL REPORT

2017 Annual Reports

American Electric Power Company, Inc. and Subsidiary Companies

AEP Texas Inc. and Subsidiaries

AEP Transmission Company, LLC and Subsidiaries

Appalachian Power Company and Subsidiaries

Indiana Michigan Power Company and Subsidiaries

Ohio Power Company and Subsidiaries

Public Service Company of Oklahoma

Southwestern Electric Power Company Consolidated

Audited Financial Statements andManagement’s Discussion and Analysis of Financial Condition and Results of Operations

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIESINDEX OF ANNUAL REPORTS

Page

NumberGlossary of Terms i Forward-Looking Information v AEP Common Stock and Dividend Information vii American Electric Power Company, Inc. and Subsidiary Companies: Selected Consolidated Financial Data 1 Management’s Discussion and Analysis of Financial Condition and Results of Operations 2 Reports of Independent Registered Public Accounting Firm 67 Management’s Report on Internal Control Over Financial Reporting 70 Consolidated Financial Statements 71 AEP Texas Inc. and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 78 Report of Independent Registered Public Accounting Firm 82 Management’s Report on Internal Control Over Financial Reporting 84 Consolidated Financial Statements 85 AEP Transmission Company, LLC and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 92 Report of Independent Registered Public Accounting Firm 94 Management’s Report on Internal Control Over Financial Reporting 96 Consolidated Financial Statements 97 Appalachian Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 103 Report of Independent Registered Public Accounting Firm 107 Management’s Report on Internal Control Over Financial Reporting 109 Consolidated Financial Statements 110 Indiana Michigan Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 117 Report of Independent Registered Public Accounting Firm 121 Management’s Report on Internal Control Over Financial Reporting 123 Consolidated Financial Statements 124 Ohio Power Company and Subsidiaries: Management’s Narrative Discussion and Analysis of Results of Operations 131 Report of Independent Registered Public Accounting Firm 135 Management’s Report on Internal Control Over Financial Reporting 137 Consolidated Financial Statements 138 Public Service Company of Oklahoma: Management’s Narrative Discussion and Analysis of Results of Operations 145 Report of Independent Registered Public Accounting Firm 149 Management’s Report on Internal Control Over Financial Reporting 151 Financial Statements 152 Southwestern Electric Power Company Consolidated: Management’s Narrative Discussion and Analysis of Results of Operations 159 Report of Independent Registered Public Accounting Firm 163 Management’s Report on Internal Control Over Financial Reporting 165 Consolidated Financial Statements 166 Index of Notes to Financial Statements of Registrants 172

GLOSSARY OF TERMS

When the following terms and abbreviations appear in the text of this report, they have the meanings indicated below.

Term Meaning

AEGCo AEP Generating Company, an AEP electric utility subsidiary.AEP

American Electric Power Company, Inc., an investor-owned electric public utility holding companywhich includes American Electric Power Company, Inc. (Parent) and majority ownedconsolidated subsidiaries and consolidated affiliates.

AEP Credit

AEP Credit, Inc., a consolidated variable interest entity of AEP which securitizes accountsreceivable and accrued utility revenues for affiliated electric utility companies.

AEP Energy

AEP Energy, Inc., a wholly-owned retail electric supplier for customers in Ohio, Illinois and otherderegulated electricity markets throughout the United States.

AEP Renewables

AEP Renewables, LLC, a wholly-owned subsidiary of Energy Supply formed for the purpose ofproviding utility scale wind and solar projects whose power output is sold via long-term powerpurchase agreements to other utilities, cities and corporations.

AEP System American Electric Power System, an electric system, owned and operated by AEP subsidiaries.AEP Texas AEP Texas Inc., an AEP electric utility subsidiary.AEP Transmission Holdco AEP Transmission Holding Company, LLC, a wholly-owned subsidiary of AEP.AEP Utilities

AEP Utilities, Inc., a former subsidiary of AEP and holding company for TCC, TNC and CSWEnergy, Inc. Effective December 31, 2016, TCC and TNC were merged into AEP Utilities,Inc. Subsequently following this merger, the assets and liabilities of CSW Energy, Inc. weretransferred to a competitive affiliate company and AEP Utilities, Inc. was renamed AEP TexasInc.

AEPEP

AEP Energy Partners, Inc., a subsidiary of AEP dedicated to wholesale marketing and trading,hedging activities, asset management and commercial and industrial sales in the deregulatedOhio and Texas market.

AEPRO AEP River Operations, LLC, a commercial barge operation sold in November 2015.AEPSC

American Electric Power Service Corporation, an AEP service subsidiary providing management

and professional services to AEP and its subsidiaries.AEPTCo

AEP Transmission Company, LLC, and its consolidated State Transcos, a subsidiary of AEPTransmission Holdco.

AEPTCo Parent

AEP Transmission Company, LLC, the holding company of the State Transcos within theAEPTCo consolidation.

AFUDC Allowance for Funds Used During Construction.AGR

AEP Generation Resources Inc., a competitive AEP subsidiary in the Generation & Marketing

segment.ALJ Administrative Law Judge.AOCI Accumulated Other Comprehensive Income.APCo Appalachian Power Company, an AEP electric utility subsidiary.Appalachian Consumer Rate Relief

Funding

Appalachian Consumer Rate Relief Funding LLC, a wholly-owned subsidiary of APCo and aconsolidated variable interest entity formed for the purpose of issuing and servicingsecuritization bonds related to the under-recovered ENEC deferral balance.

APSC Arkansas Public Service Commission.ASU Accounting Standards Update.CAA Clean Air Act.CAIR Clean Air Interstate Rule.CLECO Central Louisiana Electric Company, a nonaffiliated utility company.CO2 Carbon dioxide and other greenhouse gases.Cook Plant Donald C. Cook Nuclear Plant, a two-unit, 2,278 MW nuclear plant owned by I&M.

i

Term Meaning

CRES provider

Competitive Retail Electric Service providers under Ohio law that target retail customers byoffering alternative generation service.

CWIP Construction Work in Progress.DCC Fuel

DCC Fuel VI LLC, DCC Fuel VII, DCC Fuel VIII, DCC Fuel IX, DCC Fuel X and DCC Fuel XIconsolidated variable interest entities formed for the purpose of acquiring, owning and leasingnuclear fuel to I&M.

Desert Sky

Desert Sky Wind Farm, a 160.5 MW wind electricity generation facility located on Indian Mesa inPecos County, Texas.

DHLC Dolet Hills Lignite Company, LLC, a wholly-owned lignite mining subsidiary of SWEPCo.DIR Distribution Investment Rider.EIS

Energy Insurance Services, Inc., a nonaffiliated captive insurance company and consolidated

variable interest entity of AEP.ENEC Expanded Net Energy Cost.Energy Supply

AEP Energy Supply LLC, a nonregulated holding company for AEP’s competitive generation,

wholesale and retail businesses, and a wholly-owned subsidiary of AEP.ERCOT Electric Reliability Council of Texas regional transmission organization.ESP

Electric Security Plans, a PUCO requirement for electric utilities to adjust their rates by filing with

the PUCO.ETT

Electric Transmission Texas, LLC, an equity interest joint venture between AEP TransmissionHoldco and Berkshire Hathaway Energy Company formed to own and operate electrictransmission facilities in ERCOT.

FAC Fuel Adjustment Clause.FASB Financial Accounting Standards Board.Federal EPA United States Environmental Protection Agency.FERC Federal Energy Regulatory Commission.FGD Flue Gas Desulfurization or scrubbers.FTR

Financial Transmission Right, a financial instrument that entitles the holder to receivecompensation for certain congestion-related transmission charges that arise when the powergrid is congested resulting in differences in locational prices.

GAAP Accounting Principles Generally Accepted in the United States of America.Global Settlement

In February 2017, the PUCO approved a settlement agreement filed by OPCo in December 2016which resolved all remaining open issues on remand from the Supreme Court of Ohio inOPCo’s 2009 - 2011 and June 2012 - May 2015 ESP filings. It also resolved all open issues inOPCo’s 2009, 2014 and 2015 SEET filings and 2009, 2012 and 2013 Fuel Adjustment ClauseAudits.

I&M Indiana Michigan Power Company, an AEP electric utility subsidiary.Interconnection Agreement

An agreement by and among APCo, I&M, KPCo and OPCo, which defined the sharing of costsand benefits associated with their respective generation plants. This agreement wasterminated January 1, 2014.

IRS Internal Revenue Service.IURC Indiana Utility Regulatory Commission.KGPCo Kingsport Power Company, an AEP electric utility subsidiary.KPCo Kentucky Power Company, an AEP electric utility subsidiary.KPSC Kentucky Public Service Commission.kV Kilovolt.KWh Kilowatthour.LPSC Louisiana Public Service Commission.Market Based Mechanism

An order from the LPSC established to evaluate proposals to construct or acquire generatingcapacity. The LPSC directs that the market based mechanism shall be a request for proposalcompetitive solicitation process.

MISO Midwest Independent Transmission System Operator.

ii

Term Meaning

MLR

Member load ratio, the method used to allocate transactions among members of theInterconnection Agreement.

MMBtu Million British Thermal Units.MPSC Michigan Public Service Commission.MTM Mark-to-Market.MW Megawatt.MWh Megawatthour.Nonutility Money Pool

Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain

nonutility subsidiaries.NOx Nitrogen oxide.NSR New Source Review.OATT Open Access Transmission Tariff.OCC Corporation Commission of the State of Oklahoma.Ohio Phase-in-Recovery Funding

Ohio Phase-in-Recovery Funding LLC, a wholly-owned subsidiary of OPCo and a consolidatedvariable interest entity formed for the purpose of issuing and servicing securitization bondsrelated to phase-in recovery property.

OPCo Ohio Power Company, an AEP electric utility subsidiary.OPEB Other Postretirement Benefit Plans.Operating Agreement

Agreement, dated January 1, 1997, as amended, by and among PSO and SWEPCo governinggenerating capacity allocation, energy pricing, and revenues and costs of third partysales. AEPSC acts as the agent.

OTC Over the counter.OVEC Ohio Valley Electric Corporation, which is 43.47% owned by AEP.Parent

American Electric Power Company, Inc., the equity owner of AEP subsidiaries within the AEP

consolidation.PCA Power Coordination Agreement among APCo, I&M, KPCo and WPCo.PIRR Phase-In Recovery Rider.PJM Pennsylvania – New Jersey – Maryland regional transmission organization.PM Particulate Matter.PPA Purchase Power and Sale Agreement.Price River Rights and interests in certain coal reserves located in Carbon County, Utah.PSO Public Service Company of Oklahoma, an AEP electric utility subsidiary.PUCO Public Utilities Commission of Ohio.PUCT Public Utility Commission of Texas.Putnam

Rights and interests in certain coal reserves located in Putnam, Mason and Jackson Counties,

West Virginia.Registrant Subsidiaries

AEP subsidiaries which are SEC registrants: AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and

SWEPCo.Registrants SEC registrants: AEP, AEP Texas, AEPTCo, APCo, I&M, OPCo, PSO and SWEPCo.REP Texas Retail Electric Provider.Risk Management Contracts

Trading and nontrading derivatives, including those derivatives designated as cash flow and fair

value hedges.Rockport Plant

A generation plant, consisting of two 1,310 MW coal-fired generating units near Rockport,Indiana. AEGCo and I&M jointly-own Unit 1. In 1989, AEGCo and I&M entered into a sale-and-leaseback transaction with Wilmington Trust Company, an unrelated, unconsolidatedtrustee for Rockport Plant, Unit 2.

RSR Retail Stability Rider.RTO

Regional Transmission Organization, responsible for moving electricity over large interstate

areas.Sabine

Sabine Mining Company, a lignite mining company that is a consolidated variable interest entity

for AEP and SWEPCo.SCR Selective Catalytic Reduction, NOx reduction technology at Rockport Plant.SEC U.S. Securities and Exchange Commission.

iii

Term Meaning

SEET Significantly Excessive Earnings Test.SIA

System Integration Agreement, effective June 15, 2000, as amended, provides contractual basisfor coordinated planning, operation and maintenance of the power supply sources of thecombined AEP.

SNF Spent Nuclear Fuel.SO2 Sulfur dioxide.SPP Southwest Power Pool regional transmission organization.SSO Standard service offer.Stall Unit J. Lamar Stall Unit at Arsenal Hill Plant, a 534 MW natural gas unit owned by SWEPCo.State Transcos

AEPTCo’s seven wholly-owned, FERC regulated, transmission only electric utilities, each of

which is geographically aligned with AEP existing utility operating companies.SWEPCo Southwestern Electric Power Company, an AEP electric utility subsidiary.Tax Reform

On December 22, 2017, President Trump signed into law legislation referred to as the “Tax Cutsand Jobs Act” (the TCJA). The TCJA includes significant changes to the Internal RevenueCode of 1986, including a reduction in the corporate federal income tax rate from 35% to 21%effective January 1, 2018.

TCC Formerly AEP Texas Central Company, now a division of AEP Texas.Texas Restructuring Legislation Legislation enacted in 1999 to restructure the electric utility industry in Texas.TNC Formerly AEP Texas North Company, now a division of AEP Texas.TRA Tennessee Regulatory Authority.Transition Funding

AEP Texas Central Transition Funding II LLC and AEP Texas Central Transition Funding III LLC,wholly-owned subsidiaries of TCC and consolidated variable interest entities formed for thepurpose of issuing and servicing securitization bonds related to Texas RestructuringLegislation.

Transource Energy

Transource Energy, LLC, a consolidated variable interest entity formed for the purpose ofinvesting in utilities which develop, acquire, construct, own and operate transmission facilitiesin accordance with FERC-approved rates.

Transource Missouri A 100% wholly-owned subsidiary of Transource Energy.Trent

Trent Wind Farm, a 150 MW wind electricity generation facility located between Abilene and

Sweetwater in West Texas.Turk Plant John W. Turk, Jr. Plant, a 600 MW coal-fired plant in Arkansas that is 73% owned by SWEPCo.UMWA United Mine Workers of America.Utility Money Pool

Centralized funding mechanism AEP uses to meet the short-term cash requirements of certain

utility subsidiaries.VIE Variable Interest Entity.Virginia SCC Virginia State Corporation Commission.Wind Catcher Project

Wind Catcher Energy Connection Project, a joint PSO and SWEPCo project which includes theacquisition of a wind generation facility, totaling approximately 2,000 MW of wind generation,and the construction of a generation interconnection tie-line totaling approximately 350 miles.

WPCo Wheeling Power Company, an AEP electric utility subsidiary.WVPSC Public Service Commission of West Virginia.

iv

FORWARD-LOOKING INFORMATION

This report made by the Registrants contains forward-looking statements within the meaning of Section 21E of the Securities ExchangeAct of 1934. Many forward-looking statements appear in “Item 7 – Management’s Discussion and Analysis of Financial Condition andResults of Operations,” but there are others throughout this document which may be identified by words such as “expect,” “anticipate,”“intend,” “plan,” “believe,” “will,” “should,” “could,” “would,” “project,” “continue” and similar expressions, and include statements reflectingfuture results or guidance and statements of outlook. These matters are subject to risks and uncertainties that could cause actual resultsto differ materially from those projected. Forward-looking statements in this document are presented as of the date of thisdocument. Except to the extent required by applicable law, management undertakes no obligation to update or revise any forward-lookingstatement. Among the factors that could cause actual results to differ materially from those in the forward-looking statements are:

Ÿ Economic growth or contraction within and changes in market demand and demographic patterns in AEP service territories.Ÿ Inflationary or deflationary interest rate trends.Ÿ Volatility in the financial markets, particularly developments affecting the availability or cost of capital to finance new capital projects

and refinance existing debt.Ÿ The availability and cost of funds to finance working capital and capital needs, particularly during periods when the time lag between

incurring costs and recovery is long and the costs are material.Ÿ Electric load and customer growth.Ÿ Weather conditions, including storms and drought conditions, and the ability to recover significant storm restoration costs.Ÿ The cost of fuel and its transportation, the creditworthiness and performance of fuel suppliers and transporters and the cost of

storing and disposing of used fuel, including coal ash and spent nuclear fuel.Ÿ Availability of necessary generation capacity, the performance of generation plants and the availability of fuel, including processed

nuclear fuel, parts and service from reliable vendors.Ÿ The ability to recover fuel and other energy costs through regulated or competitive electric rates.Ÿ The ability to build transmission lines and facilities (including the ability to obtain any necessary regulatory approvals and permits)

when needed at acceptable prices and terms and to recover those costs.Ÿ New legislation, litigation and government regulation, including oversight of nuclear generation, energy commodity trading and new

or heightened requirements for reduced emissions of sulfur, nitrogen, mercury, carbon, soot or particulate matter and othersubstances that could impact the continued operation, cost recovery and/or profitability of generation plants and related assets.

Ÿ Evolving public perception of the risks associated with fuels used before, during and after the generation of electricity, includingnuclear fuel.

Ÿ Timing and resolution of pending and future rate cases, negotiations and other regulatory decisions, including rate or other recoveryof new investments in generation, distribution and transmission service, environmental compliance and excess accumulateddeferred income taxes.

Ÿ Resolution of litigation.Ÿ The ability to constrain operation and maintenance costs.Ÿ Prices and demand for power generated and sold at wholesale.Ÿ Changes in technology, particularly with respect to energy storage and new, developing, alternative or distributed sources of

generation.Ÿ The ability to recover through rates any remaining unrecovered investment in generation units that may be retired before the end of

their previously projected useful lives.Ÿ Volatility and changes in markets for capacity and electricity, coal and other energy-related commodities, particularly changes in the

price of natural gas.Ÿ Changes in utility regulation and the allocation of costs within regional transmission organizations, including ERCOT, PJM and SPP.Ÿ Changes in the creditworthiness of the counterparties with contractual arrangements, including participants in the energy trading

market.Ÿ Actions of rating agencies, including changes in the ratings of debt.Ÿ The impact of volatility in the capital markets on the value of the investments held by the pension, other postretirement benefit plans,

captive insurance entity and nuclear decommissioning trust and the impact of such volatility on future funding requirements.

v

Ÿ Accounting pronouncements periodically issued by accounting standard-setting bodies.Ÿ Impact of federal tax reform on customer rates.Ÿ Other risks and unforeseen events, including wars, the effects of terrorism (including increased security costs), embargoes, cyber

security threats and other catastrophic events.

The forward-looking statements of the Registrants speak only as of the date of this report or as of the date they are made. TheRegistrants expressly disclaim any obligation to update any forward-looking information. For a more detailed discussion of these factors,see “Risk Factors” in Part I of this report.

Investors should note that the Registrants announce material financial information in SEC filings, press releases and public conferencecalls. Based on guidance from the SEC, the Registrants may use the Investors section of AEP’s website (www.aep.com) to communicatewith investors about the Registrants. It is possible that the financial and other information posted there could be deemed to be materialinformation. The information on AEP’s website is not part of this report.

vi

AEP COMMON STOCK AND DIVIDEND INFORMATION

The AEP common stock quarterly high and low sales prices, quarter-end closing price and the cash dividends paid per share are shown inthe following table:

Quarter Ended High Low Quarter-End

Closing Price DividendDecember 31, 2017 $ 78.07 $ 69.55 $ 73.57 $ 0.62September 30, 2017 74.59 68.11 70.24 0.59June 30, 2017 72.97 66.50 69.47 0.59March 31, 2017 68.25 61.82 67.13 0.59

December 31, 2016 $ 65.25 $ 57.89 $ 62.96 $ 0.59September 30, 2016 71.32 63.56 64.21 0.56June 30, 2016 70.10 61.42 70.09 0.56March 31, 2016 66.49 56.75 66.40 0.56

AEP common stock is traded principally on the New York Stock Exchange. As of December 31, 2017, AEP had approximately 63,000registered shareholders.

vii

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIESSELECTED CONSOLIDATED FINANCIAL DATA

2017 (a) 2016 2015 2014 2013 (dollars in millions, except per share amounts)

STATEMENTS OF INCOME DATA Total Revenues $ 15,424.9 $ 16,380.1 $ 16,453.2 $ 16,378.6 $ 14,813.5 Operating Income $ 3,570.5 $ 1,207.1 $ 3,333.5 $ 3,127.4 $ 2,822.5Income from Continuing Operations $ 1,928.9 $ 620.5 $ 1,768.6 $ 1,590.5 $ 1,473.9Income (Loss) From Discontinued Operations, Net of Tax — (2.5) 283.7 47.5 10.3

Net Income 1,928.9 618.0 2,052.3 1,638.0 1,484.2 Net Income Attributable to Noncontrolling Interests 16.3 7.1 5.2 4.2 3.7

EARNINGS ATTRIBUTABLE TO AEP COMMON

SHAREHOLDERS $ 1,912.6 $ 610.9 $ 2,047.1 $ 1,633.8 $ 1,480.5

BALANCE SHEETS DATA

Total Property, Plant and Equipment $ 67,428.5 $ 62,036.6 $ 65,481.4 $ 63,605.9 $ 59,646.7Accumulated Depreciation and Amortization 17,167.0 16,397.3 19,348.2 19,970.8 19,098.6

Total Property, Plant and Equipment – Net $ 50,261.5 $ 45,639.3 $ 46,133.2 $ 43,635.1 $ 40,548.1

Total Assets $ 64,729.1 $ 63,467.7 $ 61,683.1 $ 59,544.6 $ 56,321.0 Total AEP Common Shareholders’ Equity $ 18,287.0 $ 17,397.0 $ 17,891.7 $ 16,820.2 $ 16,085.0 Noncontrolling Interests $ 26.6 $ 23.1 $ 13.2 $ 4.3 $ 0.8 Long-term Debt (b) $ 21,173.3 $ 20,256.4 $ 19,572.7 $ 18,512.4 $ 18,198.2 Obligations Under Capital Leases (b) $ 297.8 $ 305.5 $ 343.5 $ 362.8 $ 403.3

AEP COMMON STOCK DATA Basic Earnings (Loss) per Share Attributable to AEP Common

Shareholders: From Continuing Operations $ 3.89 $ 1.25 $ 3.59 $ 3.24 $ 3.02From Discontinued Operations — (0.01) 0.58 0.10 0.02

Total Basic Earnings per Share Attributable to AEP Common

Shareholders $ 3.89 $ 1.24 $ 4.17 $ 3.34 $ 3.04

Weighted Average Number of Basic Shares Outstanding (in

millions) 491.8 491.5 490.3 488.6 486.6 Market Price Range:

High $ 78.07 $ 71.32 $ 65.38 $ 63.22 $ 51.60Low $ 61.82 $ 56.75 $ 52.29 $ 45.80 $ 41.83

Year-end Market Price $ 73.57 $ 62.96 $ 58.27 $ 60.72 $ 46.74 Cash Dividends Declared per AEP Common Share $ 2.39 $ 2.27 $ 2.15 $ 2.03 $ 1.95 Dividend Payout Ratio 61.44% 183.06% 51.56% 60.78% 64.14% Book Value per AEP Common Share $ 37.17 $ 35.38 $ 36.44 $ 34.37 $ 32.98

(a) The 2017 financial results include a pretax gain on the sale of merchant generation assets of $226 million and asset impairments of $87 million (see Note7 to the financial statements).

(b) Includes portion due within one year.

1

AMERICAN ELECTRIC POWER COMPANY, INC. AND SUBSIDIARY COMPANIES MANAGEMENT’S DISCUSSION AND ANALYSISOF FINANCIAL CONDITION AND

RESULTS OF OPERATIONS

EXECUTIVE OVERVIEW

Company Overview

AEP is one of the largest investor-owned electric public utility holding companies in the United States. AEP’s electric utility operatingcompanies provide generation, transmission and distribution services to more than five million retail customers in Arkansas, Indiana,Kentucky, Louisiana, Michigan, Ohio, Oklahoma, Tennessee, Texas, Virginia and West Virginia.

AEP’s subsidiaries operate an extensive portfolio of assets including:

• Approximately 219,000 miles of distribution lines that deliver electricity to 5.4 millioncustomers.

• Approximately 40,000 circuit miles of transmission lines, including approximately 2,100 circuit miles of 765 kV lines, the backboneof the electric interconnection grid in the Eastern United States.

• AEP Transmission Holdco has approximately $5.8 billion of transmission assets in-service.

• Approximately 23,000 megawatts of regulated owned generating capacity and approximately 4,800 megawatts of regulated PPAcapacity in 3 RTOs as of December 31, 2017, one of the largest complements of generation in the United States.

Customer Demand

AEP’s weather-normalized retail sales volumes for the year ended December 31, 2017 increased by 0.3% from the year ended December31, 2016. AEP’s 2017 industrial sales volumes increased 2.8% compared to 2016. The growth in industrial sales was spread across manyindustries and most operating companies. Weather-normalized residential sales decreased 1.2% and commercial sales decreased by0.8% in 2017, respectively, from 2016.

In 2018, AEP anticipates weather-normalized retail sales volumes will increase by 0.2%. The industrial class is expected to remain flat in2018, while weather-normalized residential sales volumes are projected to increase by 0.3%, primarily related to projected customergrowth. Weather-normalized commercial sales volumes are projected to increase by 0.4%.

Federal Tax Reform

In December 2017, legislation referred to as Tax Reform was signed into law. The majority of the provisions in the new legislation areeffective for taxable years beginning after December 31, 2017. Tax Reform includes significant changes to the Internal Revenue Code of1986 (as amended, the Code), including amendments which significantly change the taxation of business entities and also includesprovisions specific to regulated public utilities. The more significant changes that affect the Registrants include the reduction in thecorporate federal income tax rate from 35% to 21%, and several technical provisions including, among others, limiting the utilization of netoperating losses arising after December 31, 2017 to 80% of taxable income with an indefinite carryforward period. The Tax Reformprovisions related to regulated public utilities generally allow for the continued deductibility of interest expense, eliminate bonusdepreciation for certain property acquired after September 27, 2017 and continue certain rate normalization requirements for accelerateddepreciation benefits.

Changes in the Code due to Tax Reform had a material impact on the Registrants’ 2017 financial statements. As a result of Tax Reform,the Registrants’ deferred tax assets and liabilities were re-measured using the newly enacted tax rate of 21% in December 2017. This re-measurement resulted in a significant reduction in the Registrants’ net accumulated deferred income tax liability. With respect to theRegistrants’ regulated operations, the reduction of the net accumulated deferred income tax liability was primarily offset by acorresponding decrease in income tax related regulatory assets and an increase in income tax related regulatory liabilities because thebenefit of the lower federal

2

tax rate is expected to be provided to customers. However, when the underlying asset or liability giving rise to the temporary differencewas not previously contemplated in regulated rates, the re-measurement of the deferred taxes on those assets or liabilities was recordedas an adjustment to income tax expense. For the Registrants’ unregulated operations, the re-measurement of deferred taxes arising fromthose operations was recorded as an adjustment to income tax expense.

The following tables provide a summary of the impact of Tax Reform on the Registrants’ 2017 financial statements.

Year EndedDecember 31, 2017 AEP AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo

(in millions)Decrease in Deferred Income Tax

Liabilities $ 6,101.1 $ 807.1 $ 558.6 $ 1,296.4 $ 808.7 $ 743.1 $ 538.6 $ 782.9

This decrease in deferred income tax liabilities resulted in an increase in income tax related regulatory liabilities, a decrease in income taxrelated regulatory assets and an adjustment to income tax expense as shown in the table below.

Year EndedDecember 31, 2017 AEP (c) AEP Texas AEPTCo APCo I&M OPCo PSO SWEPCo

(in millions)Increase (Decrease) in Income

Tax Expense (a) $ (16.5) $ (117.4) (b) $ 0.6 $ 5.7 $ 2.3 $ (14.3) (b) $ 2.8 $ 0.7Decrease in Regulatory Assets 470.2 12.1 66.9 129.1 85.3 62.7 8.3 69.8Increase in Regulatory

Liabilities 5,614.4 677.6 492.3 1,173.0 725.7 666.1 533.1 713.8

(a) In 2017, in contemplation of corporate federal tax reform, the Registrants adopted a method under Internal Revenue Section 162 for deducting repair andmaintenance costs associated with transmission and distribution property. This change resulted in a decrease in state income tax expense of approximately $10million that has been excluded from the tables above.

(b) AEP Texas and OPCo recorded favorable adjustments to income tax expense of approximately $113 million and $16 million related to previously ownedderegulated generation assets and certain deferred fuel amounts, respectively.

(c) The effect of Tax Reform on AEP’s other business operations (other than the Registrant Subsidiaries), which primarily include unregulated activities in theGeneration & Marketing segment, transmission operations reflected in the AEP Transmission Holdco segment and activities recorded in Corporate and Other,increased income tax expense for the year-ended December 31, 2017 by approximately $103 million.

Regulatory Treatment

As a result of Tax Reform, the Registrants recognized a regulatory liability for approximately $4.4 billion of excess accumulated deferredincome taxes (Excess ADIT), as well as an incremental liability of $1.2 billion to reflect the $4.4 billion Excess ADIT on a pre-tax basis. TheExcess ADIT is reflected on a pre-tax basis to appropriately contemplate future tax consequences in the periods when the regulatoryliability is settled. Approximately $3.2 billion of the Excess ADIT relates to temporary differences associated with depreciable property. TheTax Reform legislation includes certain rate normalization requirements that stipulate how the portion of the total Excess ADIT that isrelated to certain depreciable property must be passed back to customers. Specifically, for AEP’s regulated public utilities that are subjectto those rate normalization requirements, Excess ADIT resulting from the reduction of the corporate tax rate with respect to priordepreciation or recovery deductions on property will be normalized using the average rate assumption method. As a result, once theamortization of this Excess ADIT is reflected in rates, customers will receive the benefits over the remaining weighted average useful life ofthe applicable property.

For the remaining $1.2 billion of Excess ADIT, the Registrants expect to continue working with each state regulatory commission todetermine the appropriate mechanism and time period over which to provide the benefits of Tax Reform to customers.

3

The Registrants expect the mechanism and time period to provide the benefits of Tax Reform to customers will vary by jurisdiction and isnot expected to have a material impact on future net income. However, the Registrants anticipate a decrease in future cash flows primarilydue to the elimination of bonus depreciation, the reduction in the federal tax rate from 35% to 21% and the flow back of Excess ADIT.Further, the Registrants expect that access to capital markets will be sufficient to satisfy any liquidity needs that result from any suchdecrease in future cash flows.

State Regulatory Matters

Various state utility commissions have recently issued orders requiring public utilities, including the Registrants, to record regulatoryliabilities to reflect the corporate federal income taxes currently collected in utility rates in excess of the enacted corporate federal incometax rate of 21% beginning January 1, 2018. See Note 4 - Rate Matters for additional information regarding state utility commission ordersreceived impacting the Registrant Subsidiaries.

Merchant Generation Assets

In September 2016, AEP signed an agreement to sell Darby, Gavin, Lawrenceburg and Waterford Plants (“Disposition Plants”) totaling5,329 MWs of competitive generation to a nonaffiliated party. The sale closed in January 2017 for approximately $2.2 billion. The netproceeds from the transaction were approximately $1.2 billion in cash after taxes, repayment of debt associated with these assets andtransaction fees, which resulted in an after tax gain of approximately $129 million. AEP primarily used these proceeds to reduceoutstanding debt and invest in its regulated businesses, including transmission and contracted renewable projects.

The assets and liabilities included in the sale transaction have been recorded as Assets Held for Sale and Liabilities Held for Sale,respectively, on the balance sheet as of December 31, 2016. See “Dispositions” and “Assets and Liabilities Held for Sale” sections of Note7 for additional information.

In February 2017, AEP signed an agreement to sell its 25.4% ownership share of Zimmer Plant to Dynegy Corporation. Simultaneously,AEP signed an agreement to purchase Dynegy Corporation’s 40% ownership share of Conesville Plant, Unit 4. The transactions closed inthe second quarter of 2017 and did not have a material impact on net income, cash flows or financial condition.

In December 2017, AEP signed an amendment to the Cardinal Station Agreement with Buckeye Power Incorporated, which terminatescertain commercial arrangements between the parties and transitions management oversite and administrative support of the Cardinalfacility from AEP to Buckeye Power Incorporated. The amendment required approval from Rural Utilities Service and the FERC, whichwere obtained in February 2018. The new amendment will be effective March 2018 and is not expected to have a material impact on netincome, cash flows or financial condition.

Management continues to evaluate potential alternatives for the remaining merchant generation assets. These potential alternatives mayinclude, but are not limited to, transfer or sale of AEP’s ownership interests, or a wind down of merchant coal-fired generation fleetoperations. Management has not set a specific time frame for a decision on these assets. These alternatives could result in additionallosses which could reduce future net income and cash flows and impact financial condition.

Renewable Generation Portfolio

The growth of AEP’s renewable generation portfolio reflects the company’s strategy to diversify generation resources to provide cleanenergy options to customers that meet both their energy and capacity needs.

Contracted Renewable Generation Facilities

AEP is further developing its renewable portfolio within the Generation & Marketing segment. Activities include working directly withwholesale and large retail customers to provide tailored solutions based upon market knowledge, technology innovations and dealstructuring which may include distributed solar, wind, combined heat and power,

4

energy storage, waste heat recovery, energy efficiency, peaking generation and other forms of cost reducing energy technologies. Projects are pursued where a suitable termed agreement is entered into with a creditworthy counterparty. Generation & Marketing alsodevelops and/or acquires large scale renewable generation projects that are backed with long-term contracts with creditworthycounterparties. As of December 31, 2017, subsidiaries within AEP’s Generation & Marketing segment have approximately 489 MWs ofcontracted renewable generation projects in operation. In addition, as of December 31, 2017, these subsidiaries have approximately 34MWs of new renewable generation projects under construction and estimated capital costs of $61 million related to these projects.

In January 2018, AEP entered into a partnership with a non-affiliate to own and repower Desert Sky and Trent, which is expected to becompleted in 2018. The non-affiliate partner contributed full turbine sets to each project in exchange for a 20% interest in the partnership.AEP’s 80% share of the partnership, or 248 MWs, represents $232 million of additional estimated capital, of which $90 million has beenspent and is recorded in construction work in progress as of December 31, 2017. The partnership is subject to a put and a call after certainconditions are met, either of which would liquidate the non-affiliated partner’s interest.

Regulated Renewable Generation Facilities

In July 2017, APCo submitted filings with the Virginia SCC and the WVPSC requesting regulatory approval to acquire two wind generationfacilities totaling approximately 225 MWs of wind generation. The wind generating facilities are located in West Virginia and Ohio and, ifapproved, are anticipated to be in-service in the second half of 2019. APCo will assume ownership of the facilities at or near theanticipated in-service date. APCo currently plans to sell the Renewable Energy Certificates associated with the generation from thesefacilities. In December 2017, the WVPSC staff and an industrial intervenor filed testimony in West Virginia and the Virginia SCC staff filedtestimony in Virginia arguing that APCo’s forecast of natural gas and energy prices was too high and, with the exception of the WVPSCstaff’s recommended approval of the facility located in West Virginia, do not support approval of APCo’s acquisition of the facilities. InJanuary 2018, APCo filed supplemental testimony with the WVPSC to address changes in the economics of the wind projects as a resultof Tax Reform. A hearing at the Virginia SCC was held in February 2018 and a hearing is scheduled at the WVPSC in March 2018.

In July 2017, PSO and SWEPCo submitted filings with the OCC, LPSC, APSC and PUCT requesting various regulatory approvals neededto proceed with the Wind Catcher Project. The Wind Catcher Project includes the acquisition of a wind generation facility, totalingapproximately 2,000 MWs of wind generation, and the construction of a generation interconnection tie-line totaling approximately 350miles. Total investment for the project is estimated to be $4.5 billion and will serve both retail and FERC wholesale load. PSO andSWEPCo will have a 30% and 70% ownership share, respectively, in these assets. The wind generating facility is located in Oklahomaand, if approved by all state commissions, is anticipated to be in-service by the end of 2020. In July 2017, the LPSC approved SWEPCo’srequest for an exemption to the Market Based Mechanism. In August 2017, the Oklahoma Attorney General filed a motion to dismiss withthe OCC. In August 2017, the motion to dismiss was denied by the OCC. In December 2017, the Oklahoma Attorney General’s motion todismiss was renewed and again denied by the OCC. Also in December 2017, the companies filed a request at FERC to transfer the windgeneration facility to PSO and SWEPCo upon its construction by a third party, subject to the approval of the project at the respective statecommissions. Parties’ testimony filed in the Oklahoma, Texas and Louisiana dockets generally opposes the companies’ request. In thecompanies’ rebuttal testimony filed in Oklahoma, Texas, Arkansas and Louisiana, certain commitments have been made related to thecost of the investment and operational performance. In addition, PSO and SWEPCo committed in each jurisdiction to the timely filing of abase rate case to shorten the duration of cost recovery through a temporary mechanism.

In February 2018, the ALJ in Oklahoma recommended that PSO’s request for preapproval of future recovery of Wind Catcher Projectcosts be denied. Also in February 2018, SWEPCo announced a settlement agreement with the APSC staff, the Arkansas Attorney Generaland other parties in SWEPCo’s request for approval of the Wind Catcher Project. SWEPCo agreed to certain commitments related to thecost of the investment, qualification for 100% of the Production Tax Credits and operational performance. The parties filed a joint motionasking the APSC to approve the Wind Catcher Project under the terms of the settlement agreement.

5

Hurricane Harvey

In August 2017, Hurricane Harvey hit the coast of Texas, causing power outages in the AEP Texas service territory. As rebuilding effortscontinue, AEP Texas’ total costs related to this storm are not yet final. AEP Texas’ current estimated cost is approximately $325 million to$375 million, including capital expenditures. AEP Texas has a PUCT approved catastrophe reserve which allows for the deferral ofincremental storm expenses as a regulatory asset, and currently recovers approximately $1 million annually through base rates. As ofDecember 31, 2017, the total balance of AEP Texas’ catastrophe reserve deferral is $123 million, inclusive of approximately $100 millionof net incremental storm expenses related to Hurricane Harvey. AEP Texas currently estimates that it will incur approximately $12 millionof additional incremental expense related to Hurricane Harvey service restoration efforts. As of December 31, 2017, AEP Texas hasrecorded approximately $133 million of capital expenditures related to Hurricane Harvey. Also, as of December 31, 2017, AEP Texas hasreceived $10 million in insurance proceeds, which were applied to the regulatory asset and property, plant and equipment. Management,in conjunction with the insurance adjusters, is reviewing all damages to determine the extent of coverage for additional insurancereimbursement. Any future insurance recoveries received will also be applied to, and will offset, the regulatory asset and property, plantand equipment, as applicable. Management believes the amount recorded as a regulatory asset is probable of recovery and AEP Texas iscurrently evaluating recovery options for the regulatory asset. The other named 2017 hurricanes did not have a material impact on AEP’soperations. If the ultimate costs of the incident are not recovered by insurance or through the regulatory process, it would have an adverseeffect on future net income, cash flows and financial condition.

June 2015 - May 2018 ESP Including PPA Application and Proposed ESP Extension through 2024

In March 2016, a contested stipulation agreement related to the PPA rider application was modified and approved by the PUCO. Theapproved PPA rider is subject to audit and review by the PUCO. Consistent with the terms of the modified and approved stipulationagreement, and based upon a September 2016 PUCO order, in November 2016, OPCo refiled its amended ESP extension application andsupporting testimony. The amended filing proposed to extend the ESP through May 2024 and included (a) an extension of the OVEC PPArider, (b) a proposed 10.41% return on common equity on capital costs for certain riders, (c) the continuation of riders previously approvedin the June 2015 - May 2018 ESP, (d) proposed increases in rate caps related to OPCo’s DIR and (e) the addition of various new riders,including a Renewable Resource Rider.

In August 2017, OPCo and various intervenors filed a stipulation agreement with the PUCO. The stipulation extends the term of the ESPthrough May 2024 and includes: (a) an extension of the OVEC PPA rider, (b) a proposed 10% return on common equity on capital costsfor certain riders, (c) the continuation of riders previously approved in the June 2015 - May 2018 ESP, (d) rate caps related to OPCo’s DIRranging from $215 million to $290 million for the periods 2018 through 2021, (e) the addition of various new riders, including a Smart CityRider and a Renewable Generation Rider, (f) a decrease in annual depreciation rates based on a depreciation study using data throughDecember 2015 and (g) amortization of approximately $24 million annually beginning January 2018 of OPCo’s excess distributionaccumulated depreciation reserve, which was $239 million as of December 31, 2015. Upon PUCO approval of the stipulation, effectiveJanuary 2018, OPCo will cease recording $39 million in annual amortization previously approved to end in December 2018 in accordancewith PUCO’s December 2011 OPCo distribution base rate case order. In the stipulation, OPCo and intervenors agree that OPCo canrequest in future proceedings a change in meter depreciation rates due to retired meters pursuant to the smart grid Phase 2 project. DIRrate caps will be reset in OPCo’s next distribution base rate case which must be filed by June 2020.

In October 2017, intervenor testimony opposing the stipulation agreement was filed recommending: (a) a return on common equity to notexceed 9.3% for riders earning a return on capital investments, (b) that OPCo should file a base distribution case concurrent with theconclusion of the current ESP in May 2018 and (c) denial of certain new riders proposed in OPCo’s ESP extension. The stipulation issubject to review by the PUCO. A hearing at the PUCO was held in November 2017. An order from the PUCO is expected in the firstquarter of 2018.

If OPCo is ultimately not permitted to fully collect all components of its ESP rates, it could reduce future net income and cash flows andimpact financial condition. See “Ohio Electric Security Plan Filings” section of Note 4 for additional information.

6

2016 SEET Filing

In December 2016, OPCo recorded a 2016 SEET provision of $58 million based upon projected earnings data for companies in thecomparable utilities risk group. In determining OPCo’s return on equity in relation to the comparable utilities risk group, managementexcluded the following items resolved in OPCo’s Global Settlement: (a) gain on the deferral of RSR costs, (b) refunds to customers relatedto the SEET remands and (c) refunds to customers related to fuel adjustment clause proceedings.

In May 2017, OPCo submitted its 2016 SEET filing with the PUCO in which management indicated that OPCo did not have significantlyexcessive earnings in 2016 based upon actual earnings data for the comparable utilities risk group.

In January 2018, the PUCO staff filed testimony that OPCo did not have significantly excessive earnings. Also in January 2018, anintervenor filed testimony recommending a $53 million refund to customers.

In February 2018, OPCo and PUCO staff filed a stipulation agreement in which both parties agreed that OPCo did not have significantlyexcessive earnings in 2016.

In February 2018, a procedural schedule was issued by the PUCO. A hearing is scheduled for April 2018 and management expects toreceive an order in the second quarter of 2018. While management believes that OPCo’s adjusted 2016 earnings were not excessive,management did not adjust OPCo’s 2016 SEET provision due to risks that the PUCO could rule against OPCo’s proposed SEETadjustments, including treatment of the Global Settlement issues described above, adjust the comparable risk group, or adopt a different2016 SEET threshold. If the PUCO orders a refund of 2016 OPCo earnings, it could reduce future net income and cash flows and impactfinancial condition. See “2016 SEET Filing” section of Note 4 for additional information.

Rockport Plant, Unit 2 SCR

In October 2016, I&M filed an application with the IURC for approval of a Certificate of Public Convenience and Necessity (CPCN) toinstall SCR technology at Rockport Plant, Unit 2 by December 2019. The equipment will allow I&M to reduce emissions of NOx fromRockport Plant, Unit 2 in order for I&M to continue to operate that unit under current environmental requirements. The estimated cost ofthe SCR project is $274 million, excluding AFUDC, to be shared equally between I&M and AEGCo. As of December 31, 2017, total costsincurred related to this project, including AFUDC, were approximately $23 million. The filing included a request for authorization for I&M todefer its Indiana jurisdictional ownership share of costs including investment carrying costs at a weighted average cost of capital (WACC),depreciation over a 10-year period as provided by statute and other related expenses. I&M proposed recovery of these costs using theexisting Clean Coal Technology Rider in a future filing subsequent to approval of the SCR project. The AEGCo ownership share of theproposed SCR project will be billable under the Rockport Unit Power Agreement to I&M and KPCo and will be subject to future regulatoryapproval for recovery.

In February 2017, the Indiana Office of Utility Consumer Counselor (OUCC) and other parties filed testimony with the IURC. The OUCCrecommended approval of the CPCN but also stated that any decision regarding recovery of any under-depreciated plant due toretirement should be fully investigated in a base rate case, not in a tracker or other abbreviated proceeding. The other partiesrecommended either denial of the CPCN or approval of the CPCN with conditions including a cap on the amount of SCR costs allowed tobe recovered in the rider and limitations on other costs related to legal issues involving the Rockport Plant, Unit 2 lease. A hearing at theIURC was held in March 2017. An order from the IURC is pending. In July 2017, I&M filed a motion with the U.S. District Court for theSouthern District of Ohio to remove the requirement to install SCR technology at Rockport Plant, Unit 2, which plaintiffs opposed. Thedistrict court has delayed the deadline for installation of the SCR technology until June 2020. In January 2018, I&M filed a supplementalmotion with the U.S. District Court for the Southern District of Ohio proposing to install the SCR at Rockport Plant, Unit 2 and achieve thefinal SO2 emission cap applicable to the plant under the consent decree by the end of 2020, before the expiration of the initial lease term.Responsive filings were filed in February 2018 and a decision is anticipated in the first quarter of 2018.

7

2017 Indiana Base Rate Case

In July 2017, I&M filed a request with the IURC for a $263 million annual increase in Indiana rates based upon a proposed 10.6% return oncommon equity with the annual increase to be implemented after June 2018. Upon implementation, this proposed annual increase wouldbe subject to a temporary offsetting $23 million annual reduction to customer bills through December 2018 for a credit adjustment riderrelated to the timing of estimated in-service dates of certain capital expenditures. The proposed annual increase includes $78 millionrelated to increased annual depreciation rates and an $11 million increase related to the amortization of certain Cook Plant and RockportPlant regulatory assets. The increase in depreciation rates includes a change in the expected retirement date for Rockport Plant, Unit 1from 2044 to 2028 combined with increased investment at the Cook Plant, including the Cook Plant Life Cycle Management Project.

In November 2017, various intervenors filed testimony that included annual revenue increase recommendations ranging from $125 millionto $152 million. The recommended returns on common equity ranged from 8.65% to 9.1%. In addition, certain parties recommendedlonger recovery periods than I&M proposed for recovery of regulatory assets and depreciation expenses related to Rockport Plant, Units 1and 2. In January 2018, in response to a January 2018 IURC request related to the impact of Tax Reform on I&M’s pending base ratecase, I&M filed updated schedules supporting a $191 million annual increase in Indiana base rates if the effect of Tax Reform wasincluded in the cost of service.

In February 2018, I&M and all parties to the case, except one industrial customer, filed a Stipulation and Settlement Agreement for a $97million annual increase in Indiana rates effective July 1, 2018 subject to a temporary offsetting reduction to customer bills throughDecember 2018 for a credit rider related to the timing of estimated in-service dates of certain capital expenditures. The one industrialcustomer agreed to not oppose the Stipulation and Settlement Agreement. The difference between I&M’s requested $263 million annualincrease and the $97 million annual increase in the Stipulation and Settlement Agreement is primarily due to lower federal income taxesas a result of the reduction in the federal income tax rate due to Tax Reform, the feedback of credits for excess deferred income taxes, a9.95% return on equity, longer recovery periods of regulatory assets, lower depreciation expense primarily for meters, and an increase inthe sharing of off-system sales margins with customers from 50% to 95%. I&M will also refund $4 million from July through December2018 for the impact of Tax Reform for the period January through June 2018. A hearing at the IURC is scheduled for March 2018. If anyof these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

2017 Michigan Base Rate Case

In May 2017, I&M filed a request with the MPSC for a $52 million annual increase in Michigan base rates based upon a proposed 10.6%return on common equity with the increase to be implemented no later than April 2018. The proposed annual increase includes $23 millionrelated to increased annual depreciation rates and a $4 million increase related to the amortization of certain Cook Plant regulatoryassets. The increase in depreciation rates is primarily due to the proposed change in the expected retirement date for Rockport Plant, Unit1 from 2044 to 2028 combined with increased investment at the Cook Plant related to the Life Cycle Management Project. Additionally, thetotal proposed increase includes incremental costs related to the Cook Plant Life Cycle Management Program and increased vegetationmanagement expenses.

In October 2017, the MPSC staff and intervenors filed testimony. The MPSC staff recommended an annual net revenue increase of $49million including proposed retirement dates of 2028 for both Rockport Plant, Units 1 (from 2044) and 2 (from 2022), a reduced capacitycharge and a return on common equity of 9.8%. The intervenors proposed certain adjustments to I&M’s request including no change to thecurrent 2044 retirement date of Rockport Plant, Unit 1, a market based capacity charge effective February 2019 for up to 10% of I&M’sMichigan customers, but did not address an annual net revenue increase. The intervenors’ recommended returns on common equityranged from 9.3% to 9.5%. A hearing at the MPSC was held in November 2017.

In February 2018, an MPSC ALJ issued a Proposal for Decision and recommended an annual revenue increase of $49 million, includingthe intervenors’ proposed capacity charge and staff’s depreciation rates for Rockport Plant and a

8

return on common equity of 9.8%. If the maximum 10% of customers choose an alternate supplier starting in February 2019, the estimatedannual pretax loss due to the reduced capacity charge is approximately $9 million. An order is expected in the first half of 2018. If any ofthese costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

Merchant Portion of Turk Plant

SWEPCo constructed the Turk Plant, a base load 600 MW pulverized coal ultra-supercritical generating unit in Arkansas, which wasplaced into service in December 2012 and is included in the Vertically Integrated Utilities segment. SWEPCo owns 73% (440 MWs) of theTurk Plant and operates the facility.

The APSC granted approval for SWEPCo to build the Turk Plant by issuing a Certificate of Environmental Compatibility and Public Need(CECPN) for the SWEPCo Arkansas jurisdictional share of the Turk Plant (approximately 20%). Following an appeal by certainintervenors, the Arkansas Supreme Court issued a decision that reversed the APSC’s grant of the CECPN. In June 2010, in response toan Arkansas Supreme Court decision, the APSC issued an order which reversed and set aside the previously granted CECPN. This shareof the Turk Plant output is currently not subject to cost-based rate recovery and is being sold into the wholesale market. Approximately80% of the Turk Plant investment is recovered under cost-based rate recovery in Texas, Louisiana and through SWEPCo’s wholesalecustomers under FERC-based rates. As of December 31, 2017, the net book value of Turk Plant was $1.5 billion, before cost of removal,including materials and supplies inventory and CWIP. In January 2018, SWEPCo and the LPSC staff agreed on settlement terms relatingto the prudence review of the Turk Plant. See “Louisiana Turk Plant Prudence Review” section of Note 4. If SWEPCo cannot ultimatelyrecover its investment and expenses related to the Turk Plant, it could reduce future net income and cash flows and impact financialcondition.

Louisiana Turk Plant Prudence Review

Beginning January 2013, SWEPCo’s formula rates, including the Louisiana jurisdictional share (approximately 33%) of the Turk Plant,have been collected subject to refund pending the outcome of a prudence review of the Turk Plant investment, which was placed intoservice in December 2012. In October 2017, the LPSC staff filed testimony contending that SWEPCo failed to continue to evaluate thesuspension or cancellation of the Turk Plant during its construction period. In January 2018, SWEPCo and the LPSC staff filed asettlement, subject to LPSC approval, providing for a $19 million pretax write-off of the Louisiana jurisdictional share of previouslycapitalized Turk Plant costs and a $10 million rate refund provision for previously collected revenues associated with the disallowedportion of the Turk Plant. Based on the agreement, management concluded that the disallowance was probable resulting in a $23 millionpretax write off in the fourth quarter, consisting of a $15 million pretax impairment and an $8 million pretax provision for revenue refund.The agreement requires $2 million of the provision to be refunded to customers in the first billing cycle following LPSC approval of thesettlement and the remaining $8 million to be amortized as a cost of service reduction for customers over 5 years, effective August 1,2018. In February 2018, the LPSC approved the settlement agreement.

2017 Louisiana Formula Rate Filing

In April 2017, the LPSC approved an uncontested stipulation agreement that SWEPCo filed for its formula rate plan for test year 2015. The filing included a net annual increase not to exceed $31 million, which was effective May 2017 and includes SWEPCo’s Louisianajurisdictional share of Welsh Plant and Flint Creek Plant environmental controls which were placed in service in 2016. The net annualincrease is subject to refund. In October 2017, SWEPCo filed testimony in Louisiana supporting the prudence of its environmental controlinvestment for Welsh Plant, Units 1 and 3 and Flint Creek power plants. These environmental costs are subject to prudence review. Ahearing at the LPSC is scheduled for May 2018. If any of these costs are not recoverable, it could reduce future net income and cash flowsand impact financial condition.

9

2017 Oklahoma Base Rate Case

In June 2017, PSO filed an application for a base rate review with the OCC that requested an increase in annual revenues of $156 million,less an $11 million refund obligation, for a net increase of $145 million based upon a proposed 10% return on common equity. Theproposed base rate increase includes (a) environmental compliance investments, including recovery of previously deferred environmentalcompliance related costs currently recorded as regulatory assets, (b) Advanced Metering Infrastructure investments, (c) additional capitalinvestments and costs to serve PSO’s customers, and (d) an annual $42 million depreciation rate increase due primarily to shorter servicelives and lower net salvage estimates. As part of this filing, consistent with the OCC’s final order in its previous base rate case, PSOrequested recovery through 2040 of Northeastern Plant, Unit 3, including the environmental control investment, and the net book value ofNortheastern Plant, Unit 4 that was retired in 2016. As of December 31, 2017, the net book value of Northeastern Plant, Unit 4 was $81million.

In January 2018, the OCC issued a final order approving a net increase in Oklahoma annual revenues of $84 million, which was thenreduced by $32 million to $52 million to account for changes as a result of Tax Reform, based upon a return on common equity of 9.3%.The final order also included approval for recovery, with a debt return for investors, of the net book value of Northeastern Plant Unit 4 andan annual depreciation expense increase of $19 million, including requested recovery through 2040 of Northeastern Plant Unit 3. PSOanticipates implementing new rates in March 2018 billings.

2017 Kentucky Base Rate Case

In June 2017, KPCo filed a request with the KPSC for a $66 million annual increase in Kentucky base rates based upon a proposed10.31% return on common equity with the increase to be implemented no later than January 2018. The proposed increase included: (a)lost load since KPCo last changed base rates in July 2015, (b) incremental costs related to OATT charges from PJM not currentlyrecovered from retail ratepayers, (c) increased depreciation expense including updated Big Sandy Plant, Unit 1 depreciation rates using aproposed retirement date of 2031, (d) recovery of other Big Sandy Plant, Unit 1 generation costs currently recovered through a retail riderand (e) incremental purchased power costs. Additionally, KPCo requested a $4 million annual increase in environmental surchargerevenues. In August 2017, KPCo submitted a supplemental filing with the KPSC that decreased the proposed annual base rate revenuerequest to $60 million. The modification was due to lower interest expense related to June 2017 debt refinancings.

In November 2017, KPCo filed a non-unanimous settlement agreement with the KPSC. The settlement agreement included a proposedannual base rate increase of $32 million based upon a 9.75% return on common equity.

In January 2018, the KPSC issued an order approving the non-unanimous settlement agreement with certain modifications resulting in anannual revenue increase of $12 million, effective January 2018, based on a 9.7% ROE. The KPSC’s primary revenue requirementmodification to the settlement agreement was a $14 million annual revenue reduction for the decrease in the corporate federal income taxrate due to Tax Reform. The KPSC approved: (a) the deferral of $50 million of Rockport Plant Unit Power Agreement expenses for theyears 2018 through 2022, with recovery of the deferral to be addressed in KPCo’s next base rate case, (b) the recovery/return of 80% ofcertain annual PJM OATT expenses above/below the corresponding level recovered in base rates, (c) KPCo’s commitment to not file abase rate case for three years and (d) increased depreciation expense based upon updated Big Sandy Plant, Unit 1 depreciation ratesusing a 20-year depreciable life.

In February 2018, KPCo filed with the KPSC for rehearing of the January 2018 base case order and requested an additional $2.3 million ofannual revenue increases related to: (a) the calculation of federal income tax expense, (b) recovery of purchased power costs associatedwith forced outages and (c) capital structure adjustments. Also in February 2018, an intervenor filed for rehearing recommending that thereduced corporate federal income tax rate, as a result of Tax Reform, be reflected in lower purchased power expense related to theRockport UPA. It is anticipated that the KPSC will rule upon this rehearing request in the first quarter of 2018.

10

2016 Texas Base Rate Case

In December 2016, SWEPCo filed a request with the PUCT for a net increase in Texas annual revenues of $69 million based upon a 10%return on common equity. In January 2018, the PUCT issued a final order approving a net increase in Texas annual revenues of $50million based upon a return on common equity of 9.6%, effective May 2017. The final order also included (a) approval to recover the Texasjurisdictional share of environmental investments placed in service, as of June 30, 2016, at various plants, including Welsh Plant, Units 1and 3, (b) approval of recovery of, but no return on, the Texas jurisdictional share of the net book value of Welsh Plant, Unit 2, (c)approval of $2 million additional vegetation management expenses and (d) the rejection of SWEPCo’s proposed transmission costrecovery mechanism.

As a result of the final order, in the fourth quarter, SWEPCo (a) recorded an impairment charge of $19 million, which includes $7 millionassociated with the lack of return on Welsh Plant, Unit 2 and $12 million related to other disallowed plant investments (b) recognized $32million of additional revenues, for the period of May 2017 through December 2017, that will be surcharged to customers and (c)recognized an additional $7 million of expenses consisting primarily of depreciation expense and vegetation management expense, offsetby the deferral of rate case expenses. SWEPCo implemented new rates in February 2018 billings. The $32 million of additional 2017revenues will be collected by the end of 2018. In addition, SWEPCo is required to file a refund tariff within 120 days to reflect thedifference between rates collected under the final order and the rates that would be collected under Tax Reform.

Virginia Legislation Affecting Biennial Reviews

In 2015, amendments to Virginia law governing the regulation of investor-owned electric utilities were enacted. Under the amendedVirginia law, APCo’s existing generation and distribution base rates are frozen until after the Virginia SCC rules on APCo’s next biennialreview, which APCo will file in March 2020 for the 2018 and 2019 test years. These amendments also precluded the Virginia SCC fromperforming biennial reviews of APCo’s earnings for the years 2014 through 2017.

In February 2018, legislation separately passed the Virginia House of Delegates and the Senate of Virginia and, if enacted and signed intolaw by the Governor in its present form, will: (a) require APCo to not recover $10 million of fuel expenses incurred after July 1, 2018, (b)reduce APCo’s base rates by $50 million annually, on an interim basis and subject to true-up, effective July 30, 2018 related to TaxReform and (c) require an adjustment in APCo’s base rates on April 1, 2019 to reflect actual annual reductions in corporate income taxesdue to Tax Reform. APCo’s next base rate review in 2020 will now include a review of earnings for test years 2017-2019, with triennialreviews of APCo’s base rates and earnings thereafter instead of biennial reviews. The current VA legislative session is scheduled toadjourn in March 2018. Either a biennial review of 2018-2019 or a triennial review of 2017-2019 could reduce future net income and cashflows and impact financial condition.

FERC Transmission Complaint - AEP’s PJM Participants

In October 2016, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s easterntransmission subsidiaries in calculating formula transmission rates under the PJM OATT is excessive and should be reduced from 10.99%to 8.32%, effective upon the date of the complaint. Management believes its financial statements adequately address the impact of thecomplaint. In November 2017, a FERC Order set the matter for hearing and settlement procedures. If the FERC orders revenue reductionsas a result of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows andimpact financial condition.

Modifications to AEP’s PJM Transmission Rates

In November 2016, AEP’s eastern transmission subsidiaries filed an application at the FERC to modify the PJM OATT formulatransmission rate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projectedexpenses. In March 2017, the FERC accepted the proposed modifications effective January 1, 2017, subject to refund, and set this matterfor hearing and settlement procedures. The modified PJM OATT formula rates are based on projected calendar year financial activity andprojected plant balances. In December 2017, AEP’s

11

eastern transmission subsidiaries filed an uncontested settlement agreement with the FERC resolving all outstanding issues. If the FERCdetermines that any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition.

FERC Transmission Complaint - AEP’s SPP Participants

In June 2017, several parties filed a complaint at the FERC that states the base return on common equity used by AEP’s westerntransmission subsidiaries in calculating formula transmission rates under the SPP OATT is excessive and should be reduced from 10.7%to 8.36%, effective upon the date of the complaint. In November 2017, a FERC order set the matter for hearing and settlement procedures.Management believes its financial statements adequately address the impact of the complaint. If the FERC orders revenue reductions as aresult of the complaint, including refunds from the date of the complaint filing, it could reduce future net income and cash flows and impactfinancial condition.

Modifications to AEP’s SPP Transmission Rates

In October 2017, AEP’s western transmission subsidiaries filed an application at the FERC to modify the SPP OATT formula transmissionrate calculation, including an adjustment to recover a tax-related regulatory asset and a shift from historical to projected expenses. Themodified SPP OATT formula rates are based on projected 2018 calendar year financial activity and projected plant balances. In December2017, the FERC accepted the proposed modifications effective January 1, 2018, subject to refund, and set this matter for hearing andsettlement procedures. If the FERC determines that any of these costs are not recoverable, it could reduce future net income and cashflows and impact financial condition.

FERC SWEPCo Power Supply Agreements Complaint - East Texas Electric Cooperative, Inc. (ETEC) and Northeast TexasElectric Cooperative, Inc. (NTEC)

In September 2017, ETEC and NTEC filed a complaint at the FERC that states the base return on common equity used by SWEPCo incalculating their power supply formula rates is excessive and should be reduced from 11.1% to 8.41%, effective upon the date of thecomplaint. In November 2017, a FERC order set the matter for hearing and settlement procedures. Management believes its financialstatements adequately address the impact of the complaint. If the FERC orders revenue reductions as a result of the complaint, includingrefunds from the date of the complaint filing, it could reduce future net income and cash flows and impact financial condition.

Welsh Plant - Environmental Impact

Management currently estimates that the investment necessary to meet proposed environmental regulations through 2025 for WelshPlant, Units 1 and 3 could total approximately $850 million, excluding AFUDC. As of December 31, 2017, SWEPCo had incurred costs of$398 million, including AFUDC, related to these projects. Management continues to evaluate the impact of environmental rules andrelated project cost estimates. As of December 31, 2017, the total net book value of Welsh Plant, Units 1 and 3 was $627 million, beforecost of removal, including materials and supplies inventory and CWIP.

In 2016, as approved by the APSC, SWEPCo began recovering $79 million related to the Arkansas jurisdictional share of theseenvironmental costs, subject to prudence review in the next Arkansas filed base rate proceeding. In April 2017, the LPSC approvedrecovery of $131 million in investments related to its Louisiana jurisdictional share of environmental controls installed at Welsh Plant,effective May 2017. SWEPCo’s approved Louisiana jurisdictional share of Welsh Plant deferrals: (a) are $11 million, excluding $6 millionof unrecognized equity as of December 31, 2017, (b) is subject to review by the LPSC, and (c) includes a WACC return on environmentalinvestments and the related depreciation expense and taxes. In January 2018, SWEPCo received written approval from the PUCT torecover its project costs from retail customers in its 2016 Texas base rate case and is recovering these costs from wholesale customersthrough SWEPCo’s FERC-approved agreements. See “2016 Texas Base Rate Case” and “2017 Louisiana Formula Rate Filing”disclosures above.

If any of these costs are not recoverable, it could reduce future net income and cash flows and impact financial condition. See “WelshPlant - Environmental Impact” section of Note 4 for additional information.

12

Westinghouse Electric Company Bankruptcy Filing

In March 2017, Westinghouse filed a petition to reorganize under Chapter 11 of the U.S. Bankruptcy Code. It intends to reorganize, notcease business operations. However, it is in the early stages of the bankruptcy process and it is unclear whether the company cansuccessfully reorganize. Westinghouse and I&M have a number of significant ongoing contracts relating to reactor services, nuclear fuelfabrication and ongoing engineering projects. The most significant of these relate to Cook Plant fuel fabrication. Westinghouse has statedthat it intends to continue performance on I&M’s contracts, but given the importance of upcoming dates in the fuel fabrication process forCook Plant, and their vital part in Cook Plant’s ongoing operations, I&M continues to work with Westinghouse in the bankruptcyproceedings to avoid any interruptions to that service.

In January 2018, Westinghouse issued a news release stating that it intends to sell all of its global business, including the portion of thenuclear business that contracts with Cook Plant. Any sale would require approval by the bankruptcy court. In the unlikely eventWestinghouse rejects I&M’s contracts, or there is an interference with the sale process, Cook Plant’s operations would be significantlyimpacted and potentially shut down temporarily as I&M seeks other vendors for these services.

LITIGATION

In the ordinary course of business, AEP is involved in employment, commercial, environmental and regulatory litigation. Since it is difficultto predict the outcome of these proceedings, management cannot predict the eventual resolution, timing or amount of any loss, fine orpenalty. Management assesses the probability of loss for each contingency and accrues a liability for cases that have a probable likelihoodof loss if the loss can be estimated. For details on the regulatory proceedings and pending litigation see Note 4 – Rate Matters and Note 6– Commitments, Guarantees and Contingencies. Adverse results in these proceedings have the potential to reduce future net income andcash flows and impact financial condition.

Rockport Plant Litigation

In July 2013, the Wilmington Trust Company filed a complaint in U.S. District Court for the Southern District of New York against AEGCoand I&M alleging that it will be unlawfully burdened by the terms of the modified NSR consent decree after the Rockport Plant, Unit 2 leaseexpiration in December 2022. The terms of the consent decree allow the installation of environmental emission control equipment,repowering or retirement of the unit. The plaintiffs further allege that the defendants’ actions constitute breach of the lease andparticipation agreement. The plaintiffs seek a judgment declaring that the defendants breached the lease, must satisfy obligations relatedto installation of emission control equipment and indemnify the plaintiffs. The New York court granted a motion to transfer this case to theU.S. District Court for the Southern District of Ohio. In October 2013, a motion to dismiss the case was filed on behalf of AEGCo and I&M.

In January 2015, the court issued an opinion and order granting the motion in part and denying the motion in part. The court dismissedcertain of the plaintiffs’ claims, including the dismissal without prejudice of plaintiffs’ claims seeking compensatory damages. Severalclaims remained, including the claim for breach of the participation agreement and a claim alleging breach of an implied covenant of goodfaith and fair dealing. In June 2015, AEGCo and I&M filed a motion for partial judgment on the claims seeking dismissal of the breach ofparticipation agreement claim as well as any claim for indemnification of costs associated with this case. The plaintiffs subsequently filedan amended complaint to add another claim under the lease and also filed a motion for partial summary judgment. In November 2015,AEGCo and I&M filed a motion to strike the plaintiffs’ motion for partial judgment and filed a motion to dismiss the case for failure to state aclaim.

In March 2016, the court entered an opinion and order in favor of AEGCo and I&M, dismissing certain of the plaintiffs’ claims for breach ofcontract and dismissing claims for breach of implied covenant of good faith and fair dealing, and further dismissing plaintiffs’ claim forindemnification of costs. By the same order, the court permitted plaintiffs to move forward with their claim that AEGCo and I&M failed toexercise prudent utility practices in the maintenance and operation of Rockport Plant, Unit 2. In April 2016, the plaintiffs filed a notice ofvoluntary dismissal of all remaining

13

claims with prejudice and the court subsequently entered a final judgment. In May 2016, plaintiffs filed an appeal in the U.S. Court ofAppeals for the Sixth Circuit on whether AEGCo and I&M are in breach of certain contract provisions that plaintiffs allege operate toprotect the plaintiffs’ residual interests in the unit and whether the trial court erred in dismissing plaintiffs’ claims that AEGCo and I&Mbreached the covenant of good faith and fair dealing.

In April 2017, the U.S. Court of Appeals for the Sixth Circuit issued an opinion reversing the district court’s decisions which had dismissedcertain of plaintiffs’ claims for breach of contract and remanding the case to the district court to enter summary judgment in plaintiffs’ favorconsistent with that ruling. In April 2017, AEGCo and I&M filed a petition for rehearing with the U.S. Court of Appeals for the Sixth Circuit,which was granted. In June 2017, the U.S. Court of Appeals for the Sixth Circuit issued an amended opinion and judgment which reversesthe district court’s dismissal of certain of the owners’ claims under the lease agreements, vacates the denial of the owners’ motion forpartial summary judgment and remands the case to the district court for further proceedings. The amended opinion and judgment alsoaffirms the district court’s dismissal of the owners’ breach of good faith and fair dealing claim as duplicative of the breach of contractclaims and removes the instruction to the district court in the original opinion to enter summary judgment in favor of the owners.

In July 2017, AEP filed a motion with the U.S. District Court for the Southern District of Ohio in the original NSR litigation, seeking tomodify the consent decree to eliminate the obligation to install certain future controls at Rockport Plant, Unit 2 if AEP does not acquireownership of that Unit, and to modify the consent decree in other respects to preserve the environmental benefits of the consent decree.In November 2017, the district court granted the owners’ unopposed motion to stay the lease litigation to afford time for resolution of AEP’smotion to modify the consent decree. See “Proposed Modification of the NSR Litigation Consent Decree” section below for additionalinformation.

Management will continue to defend against the claims. Given that the district court dismissed plaintiffs’ claims seeking compensatoryrelief as premature, and that plaintiffs have yet to present a methodology for determining or any analysis supporting any alleged damages,management is unable to determine a range of potential losses that are reasonably possible of occurring.

ENVIRONMENTAL ISSUES

AEP has a substantial capital investment program and is incurring additional operational costs to comply with environmental controlrequirements. Additional investments and operational changes will need to be made in response to existing and anticipated requirementssuch as new CAA requirements to reduce emissions from fossil fuel-fired power plants, rules governing the beneficial use and disposal ofcoal combustion by-products, clean water rules and renewal permits for certain water discharges.

AEP is engaged in litigation about environmental issues, was notified of potential responsibility for the clean-up of contaminated sites andincurred costs for disposal of SNF and future decommissioning of the nuclear units. AEP, along with various industry groups, affectedstates and other parties challenged some of the Federal EPA requirements in court. Management is also engaged in the development ofpossible future requirements including the items discussed below. Management believes that further analysis and better coordination ofthese environmental requirements would facilitate planning and lower overall compliance costs while achieving the same environmentalgoals.

AEP will seek recovery of expenditures for pollution control technologies and associated costs from customers through rates in regulatedjurisdictions. Environmental rules could result in accelerated depreciation, impairment of assets or regulatory disallowances. If AEP isunable to recover the costs of environmental compliance, it would reduce future net income and cash flows and impact financial condition.

14

Environmental Controls Impact on the Generating Fleet

The rules and proposed environmental controls discussed below will have a material impact on the generating units in the AEPSystem. Management continues to evaluate the impact of these rules, project scope and technology available to achieve compliance. Asof December 31, 2017, the AEP System had a total generating capacity of approximately 25,600 MWs, of which approximately 13,500MWs are coal-fired. Management continues to refine the cost estimates of complying with these rules and other impacts of theenvironmental proposals on the fossil generating facilities. Based upon management estimates, AEP’s investment to meet these existingand proposed requirements ranges from approximately $2.1 billion to $2.7 billion through 2025.

The cost estimates will change depending on the timing of implementation and whether the Federal EPA provides flexibility in finalizingproposed rules or revising certain existing requirements. The cost estimates will also change based on: (a) the states’ implementation ofthese regulatory programs, including the potential for state implementation plans (SIPs) or federal implementation plans (FIPs) thatimpose more stringent standards, (b) additional rulemaking activities in response to court decisions, (c) the actual performance of thepollution control technologies installed on the units, (d) changes in costs for new pollution controls, (e) new generating technologydevelopments, (f) total MWs of capacity retired and replaced, including the type and amount of such replacement capacity and (g) otherfactors. In addition, management is continuing to evaluate the economic feasibility of environmental investments on both regulated andcompetitive plants.

The table below represents the plants or units of plants retired in 2016 and 2015 with a remaining net book value. As of December 31,2017, the net book value before cost of removal, including related materials and supplies inventory and CWIP balances, of the units listedbelow was approved for recovery, except for $233 million. Management is seeking or will seek recovery of the remaining net book value of$233 million in future rate proceedings.

Generating Amounts PendingCompany Plant Name and Unit Capacity Regulatory Approval

(in MWs) (in millions)APCo Kanawha River Plant 400 $ 44.8APCo Clinch River Plant, Unit 3 235 32.7APCo (a) Clinch River Plant, Units 1 and 2 470 31.8APCo Sporn Plant 600 17.2APCo Glen Lyn Plant 335 13.4I&M (b) Tanners Creek Plant 995 42.6SWEPCo Welsh Plant, Unit 2 528 50.8

Total 3,563 $ 233.3

(a) APCo obtained permits following the Virginia SCC’s and WVPSC’s approval to convert its 470 MW Clinch River Plant, Units 1 and2 to natural gas. In 2015, APCo retired the coal-related assets of Clinch River Plant, Units 1 and 2. Clinch River Plant, Unit 1 andUnit 2 began operations as natural gas units in February 2016 and April 2016, respectively.

(b) I&M requested recovery of the Indiana (approximately 65%) and Michigan (approximately 14%) jurisdictional shares of theremaining retirement costs of Tanners Creek Plant in the 2017 Indiana and Michigan base rate cases. See “2017 Indiana BaseRate Case” and “2017 Michigan Base Rate Case” sections of Note 4 for additional information.

In January 2017, Dayton Power and Light Company announced the future retirement of the 2,308 MW Stuart Plant, Units 1-4. Theretirement is scheduled for June 2018. Stuart Plant, Units 1-4 are operated by Dayton Power and Light Company and are jointly owned byAGR and nonaffiliated entities. AGR owns 600 MWs of the Stuart Plant, Units 1-4. As of December 31, 2017, AGR’s net book value of theStuart Plant, Units 1-4 was zero.

To the extent existing generation assets are not recoverable, it could materially reduce future net income and cash flows and impactfinancial condition.

15